1. Field of the Invention
This invention relates to oil and gas wellhead monitors and more particularly to apparatus and arrangements for inspecting a plunger utilized within that wellhead which permits inspection of that plunger, to determine its and the wellhead's condition.
2. Prior Art
In the life of an oil or gas well, eventually the bottom hole pressure and the gas to liquid ratio will not support a natural flow therefrom. The well operator at that time must select an “artificial lift” to remove fluid from the well so as to resume production. A “plunger lift” is a form of artificial lift which may be utilized in maintaining production levels and stabilizing the rate of decline and production of oil and gas from a well.
For such a plunger lift apparatus to be functional, there must be sufficient gas present to drive the system. Oil wells which are producing no gas are not plunger lift candidates. An industry misconception exists as to how much gas and pressure is required to successfully operate a plunger lift system. Because of this misconception, many wells have been placed on more expensive forms of an artificial lift, such as pumping units or the like, than are really needed. As a result, optimum output has not been achieved, and capital expenditures have run much higher than necessary.
As the oil flow rate and pressure decline in a well, the lifting efficiency declines geometrically. The well then may begin to “load up” and “log off”. This means that gas being produced into the well bore can no longer carry the liquid produced to the surface. The reasons for this are that as liquid comes in contact with the wall of the production string or tubing, friction will occur. The velocity of that liquid is thus slowed and some of the liquid adheres to the tubing wall, creating a film of liquid on that tubing wall. Thus, that liquid does not reach the surface of the well head.
Further, as the flow velocity continues to slow, the gas phase can no longer support liquid in either slug form or droplet form. This liquid along with the liquid film on the sides of the tubing begin to fall back to the bottom of the well. In a very aggravated situation there will be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity, very little liquid if any is carried to the surface of the well by the gas.
The corresponding head of liquid in the bottom of the well exerts a back pressure against the producing formation in a value equal to its weight, effectively terminating the well's ability to produce. A properly applied “plunger lift” system is able to bring such a well back into life and make it extremely profitable.
A plunger lift system permits the well to be opened and closed so as to generate a sufficient pressure permitting the well to flow into the flow line. The plunger within this tubing however freely travels the vertical tubing string and is used as an interface between the liquid phase and the gas phase. The use of such a plunger in the tubing, minimizes any fluid fallback over the entire length of the tubing, irrespective of that depth of the well. Such a well may be operated therefore at a lower bottom hole pressure since all the liquid is removed from the well bore, thus enhancing its production.
The plunger in this particular system travels freely back and forth, from the bottom of the well to the surface and back to the bottom. The plunger is used as a mechanical interface between the gas phase and the fluid phase in the well. When the well is closed at the surface, the plunger rests at the bottom of the well, on top of a spring assembly. When the well is opened at the surface, with all production being through the tubing, the well begins to flow and the pressure in the tubing decreases. Because the trapped gas in the casing/tubing annulus remains at a higher pressure than the tubing, the differential pressure between the two increases. The fluid level in the annulus decreases as the fluid is pushed downward where it “U tubes” into the tubing. The mechanical tolerance between the outside diameter of the plunger and the inside of the tubing leaves sufficient space for the fluid to bypass the plunger, allowing it to remain resting on the bottom. Expansion properties of gas within the tubing causes the plunger to move up the tubing string with the fluid load on top. A small amount of gas will bypass the plunger. This is useful as it scours the plunger and the tubing wall of fluid keeping all the fluid on top of the plunger. If the system has been properly engineered, virtually all the fluid can be removed from the well to permit the well to flow at the lowest production pressure possible. Thus production is consequently optimized.
At the top of the well head, there is a lubricator. The lubricator is arranged to place the plunger in the well and to retrieve the plunger from the well without having to kill the well. The lubricator may have a sensor to detect the plunger's arrival at the surface, sending a signal to a controller for various controller functions to help optimize production.
The plunger traveling through the system of the tubing however certainly suffers wear along its outer peripheral surface. The lifespan of a typical plunger may vary anywhere from about six months to about a year. There is a need to determine when to replace such a plunger so as to maximize the efficiency of the entire system. It is also therefore not always desirable to physically remove the plunger through the lubricator, to inspect it so as to otherwise slow down the operation of the well.
It is an object of the present invention to overcome the disadvantages of the prior art.
It is a further object of the present invention to provide a plunger inspection arrangement which optimizes wellhead output.
It is yet a further object of the present invention to provide a plunger which has means to indicate when it is time to be replaced.